Propped fracture with high effective surface area

ABSTRACT

Propped fractures in formations from which fluids are produced are described that have wormholes extending out into the formations from the faces of the fractures at locations distant from boreholes. Methods are given for creating such propped fractures having wormholes in which either a closed propped fracture is formed and then the wormholes are formed, or the entire fracture and channel system is formed before the closure occurs.

BACKGROUND OF INVENTION

This invention relates to improving the production of fluids from wellspenetrating subterranean formations. More specifically it relates to amethod for increasing the ability of fractures to drain formations. Inparticular it relates to propped fractures, that have wormholesextending from the faces of the fractures into the formation, andmethods of creating such fractures.

The flow of fluids through porous media, for example the production offluids from wells, is governed by three principle factors: the size ofthe flow path, the permeability of the flow path, and the driving force.

It is often necessary to stimulate the production of fluids fromsubterranean formations when wells are not producing satisfactorily. Thefailure to produce is typically due to an inadequate, or a damaged, pathfor fluids to flow from the formation to the wellbore. This may bebecause the formation inherently has insufficient porosity and/orpermeability, or because the porosity and/or permeability have beendecreased (damaged) near the wellbore during drilling and/or completionand/or production. There are two main stimulation techniques: matrixstimulation and fracturing. Matrix stimulation is accomplished byinjecting a fluid (e.g., acid or solvent) to dissolve and/or dispersematerials that impair well production in sandstones or to create new,unimpaired flow channels between the wellbore and a carbonate formation.In matrix stimulation, fluids are injected below the fracturing pressureof the formation. Matrix stimulation, typically called matrix acidizingwhen the stimulation fluid is an acid, generally is used to treat onlythe near-wellbore region. In a matrix acidizing treatment, the acid used(typically hydrochloric acid for carbonates) is injected at a pressurelow enough to prevent formation fracturing. It is desirable to take intoaccount well and formation factors (such as temperature and formationcomposition) and adjust treatment parameters (such as acid strength andinjection rate) so that dominant “wormholes” are formed which penetratethrough the near wellbore area.

When acid is pumped into a formation, such as a carbonate (limestone ordolomite) formation, at pressures below the fracture pressure, the acidflows preferentially into the highest solubility or the highestpermeability regions (that is, largest pores, vugs or naturalfractures). Acid reaction in the high-solubility or high-permeabilityregion ideally causes the formation of large, highly conductive flowchannels called wormholes that form approximately normal to thefracture. The creation of wormholes is related to the rate of chemicalreaction of the acid with the rock. High reaction rates, as observedbetween typical concentrations of unaltered mineral acids, such as HCl,and carbonates, tend to favor wormhole formation. Acids normally used infield treatments are highly reactive at reservoir conditions and tend toform a limited number of wormholes. A low reaction rate favors theformation of several small-diameter wormholes. However, unless thetreatment is designed properly, wormholes are not formed. Instead, forexample if the acid flux is too low, the acid reacts evenly with theformation, which is commonly called compact dissolution, dissolving allthe rock near the wellbore and not penetrating deep into the formationand creating flow paths there. Wormholing is desirable in matrixacidizing.

In fracturing, on the other hand, a fluid is forced into the formationat a pressure above that at which the formation rock will part. Thiscreates a greatly enlarged flow path. However, when the pressure isreleased, the fracture typically closes and the new flow path is notmaintained unless the operator provides some mechanism by which thefracture could be held open. There are two common ways of doing this. Inconventional propped hydraulic fracturing, the fluid that is used togenerate or propagate the fracture is viscous and carries a solidproppant that is trapped in the fracture when the pressure is released,preventing the fracture from closing. In acid fracturing, also known asfracture acidizing, the fracture is generated or subsequently treatedwith an acid. In this case, however, the treatment parameters have inthe past been adjusted so that wormholing did not occur. Instead, theobject previously has been to etch the faces of the fracturedifferentially. Then, when the pressure is released, the fracture doesnot close completely because the differential etching has created anasperity between the faces so that they no longer match up and there aregaps where material has been removed. Ideally the differential etchingforms flow channels, usually generally running along the faces of thefracture from the wellbore to the tip, that enhance production. In acidfracturing, wormholing was undesirable because in methods usedpreviously it does not occur at many points along the fracture butrather primarily occurs only where the acid most easily or firstcontacts the formation. This is most typically near the wellbore,although if there are natural high-conductivity streaks, fissures, vugs,etc., there could be other locations with a high intensity of wormholes.This increases the amount of acid required (wastes acid that wouldotherwise be used to etch the conductive channels) and increases thepump rates required to propagate the fracture and keep the fractureopen. Thus when there are wormholes near the wellbore in acidfracturing, large amounts of acid and high pump rates are required sothat the fluid that reaches far out into the fracture, if a fracture canbe formed at all, is still sufficiently acidic to react with thefracture faces. This situation is exacerbated by the fact that, eventhough the pump rate as seen at the wellhead can be high, the fluidvelocity out in the fracture (affecting the rate at which fresh acidreaches that point) can be very low because the surface area of thefracture faces increases greatly as the fracture is propagating.

In production from a fracture-stimulated well, the extent of theavailable flowpath is a function of the size and shape of the fracture,and in particular of the effective surface area of the faces of thefracture. The permeability of the flowpath is the effective permeabilityof the fracture after closure, that is, the effective permeability ofthe proppant pack or of the etched channels. The driving force is thepressure differential between the fluid in the formation and the fluidin the wellbore. This driving force varies along the length of thefracture. The optimal fracture would be one with a large effectivesurface area and a high effective permeability. As it relates tomaximizing production, this would be the equivalent of having a largereffective wellbore radius. It would therefore require only a smallpressure drop to provide a high fluid flow rate out of the formation andinto the wellbore.

In the past, the only way to generate a fracture with a high effectivesurface area for flow of fluids from the formation into the fracture wasto generate a fracture that was either high (assuming a verticalfracture) or long (extending far from the borehole) or both, and thebest way to generate a fracture having a high effective permeability waswith proppant. Propped fractures having wormholes extending from theirfaces out into the formation, and methods of forming such fractures,would be highly desirable because they would have high effective surfaceareas and the wells would have high effective wellbore radii.

U.S. Pat. No. 3,768,564 discloses a process wherein unpropped fracturesare allowed to close prior to prolonged contact with acid. Flow channelsare etched while the fracture is held open, then expanded only after thefracture is allowed to close. U.S. Pat. No. 3,842,911 describes the useof propping agents in this process. It describes the formation of afracture and the introduction of propping agent into the fracture,followed by the complete closure of the fracture on the propping agentand then injection of acid under conditions at which the fractureremains closed, allowing creation of flow channels a relatively longdistance from the wellbore. U.S. Pat. No. 4,245,702 describes a processof fracturing and acidizing a well with the use of propping agents thatis particularly applicable to relatively hard formations. U.S. Pat. No.3,642,068 describes the creation of a fracture by means of a viscousmedium followed by the passage of propping agents into the fracture. Theagent is shifted to a remote location in the fracture by means of anacid that etches those parts of the fracture walls that are close to theborehole. Subsequently the fracture is closed. Formation of wormholes isnot proposed in any of these fracturing methods.

SUMMARY OF INVENTION

One embodiment of the present invention is a flowpath, in a subterraneanformation penetrated by a wellbore, that has one or more proppedfractures having one or more primary channels (wormholes) extending fromthe fracture or fractures into the formation. In another embodiment,these primary channels have secondary channels (wormholes) extendingfrom them. In either of these embodiments, the fracture has an increasedeffective surface area for the inflow of fluids into the fracture fromthe formation.

Another embodiment is a method of forming such flowpaths by carrying outthe sequential steps of injecting a viscous carrier fluid containingproppant at a rate and pressure sufficient to fracture the formation andallowing the fracture to close, and then injecting aformation-dissolving fluid at a rate and pressure insufficient tofracture the formation. Especially in carbonates, theformation-dissolving fluid is preferably a self-diverting acid, anaminopolycarboxylic acid such as hydroxyethylethylenediamine triaceticacid, an aminopolycarboxylic acid salt such as trisodiumhydroxyethylethylenediamine triacetate, preferably adjusted to a pH ofabout 4 with hydrochloric acid, or a mixture of an aminopolycarboxylicacid and an aminopolycarboxylic acid salt. In sandstones, theformation-dissolving fluid preferably contains hydrofluoric acid or ahydrofluoric acid precursor, and optionally contains a phosphonate. Inthe step of injecting the viscous carrier fluid containing proppant, atip screenout may optionally be induced and a breaker may optionally beincluded in the fluid. In another embodiment, the step of injecting aformation-dissolving fluid at a rate and pressure insufficient tofracture the formation is performed remedially, that is, it is appliedto a previously created fracture, from which production of fluids mayhave been attempted or achieved.

Yet another embodiment is a method of creating such flowpaths having anincreased effective surface area for flow of fluids from the formationinto a fracture due to the presence of wormholes distant from a wellborein which a polymeric viscous carrier fluid containing proppant isinjected at a rate and pressure sufficient to fracture the formation,then a formation-dissolving viscous carrier fluid containing proppant isinjected at a rate and pressure sufficient to hold the fracture open(and optionally to propagate the fracture), and then the fracture isallowed to close. A tip screenout may optionally be induced in the firstproppant-carrying step, and either carrier fluid may optionally containa breaker. In carbonates, the formation-dissolving viscous carrier fluidis preferably a surfactant-based viscoelastic fluid, and most preferablya self-diverting acid. In sandstones, the formation-dissolving viscouscarrier fluid preferably contains hydrofluoric acid or a hydrofluoricacid precursor, and optionally contains a phosphonate.

Yet another embodiment is a method of creating such flowpaths in which aformation-dissolving viscous fluid is first injected at a rate andpressure sufficient to fracture the formation, then a viscous carrierfluid containing proppant is injected at a rate and pressure sufficientto hold the fracture open, and then the fracture is allowed to close.Especially in carbonates, the formation-dissolving viscous fluidpreferably contains a self-diverting acid, an aminopolycarboxylic acidsuch as hydroxyethylethylenediamine triacetic acid, anaminopolycarboxylic acid salt such as trisodiumhydroxyethylethylenediamine triacetate, preferably adjusted to a pH ofabout 4 with hydrochloric acid, or a mixture of an aminopolycarboxylicacid and an aminopolycarboxylic acid salt. In sandstones, theformation-dissolving viscous fluid preferably contains hydrofluoric acidor a hydrofluoric acid precursor, and optionally contains a phosphonate.Either the formation-dissolving viscous fluid, the viscous carrierfluid, or both may optionally contain a breaker.

Yet another embodiment is a method of creating such flowpaths in which aviscous carrier fluid containing proppant is first injected at a rateand pressure sufficient to fracture the formation, then aformation-dissolving fluid is injected at a rate and pressure sufficientto hold the fracture open, and then the fracture is allowed to close.Especially in carbonates, the formation-dissolving fluid is preferably aself-diverting acid, an aminopolycarboxylic acid such ashydroxyethylethylenediamine triacetic acid, an aminopolycarboxylic acidsalt such as trisodium hydroxyethylethylenediamine triacetate,preferably adjusted to a pH of about 4 with hydrochloric acid, or amixture of an aminopolycarboxylic acid and an aminopolycarboxylic acidsalt. In sandstones, the formation-dissolving fluid preferably containshydrofluoric acid or a hydrofluoric acid precursor, and optionallycontains a phosphonate. A tip screenout may optionally be induced in theproppant-carrying step, and a breaker may optionally be included in theviscous carrier fluid. Optionally, a step of injecting a viscous carrierfluid (optionally containing a breaker) containing proppant, at a rateand pressure sufficient to hold the fracture open, may be included afterthe step of injecting the formation-dissolving fluid and prior toallowing the fracture to close.

Yet another embodiment is a method of creating such flowpaths in which aformation-dissolving viscous carrier fluid containing proppant isinjected at a rate and pressure sufficient to fracture the formation,and the fracture is allowed to close. A tip screenout may optionally beinduced and the formation-dissolving viscous carrier fluid mayoptionally contain a breaker. In carbonates, the formation-dissolvingviscous carrier fluid is preferably a surfactant-based viscoelasticfluid, and most preferably a self-diverting acid. In sandstones, theformation-dissolving viscous carrier fluid preferably containshydrofluoric acid or a hydrofluoric acid precursor, and optionallycontains a phosphonate.

Yet another embodiment is a method of increasing the effective surfacearea for the inflow of fluids from an existing natural fissure that isalready in communication with a wellbore or a fracture, in which aformation-dissolving fluid is injected at a rate and pressureinsufficient to fracture the formation. In carbonates, theformation-dissolving fluid is preferably a surfactant-based viscoelasticfluid, and most preferably a self-diverting acid. In sandstones, theformation-dissolving fluid preferably contains hydrofluoric acid or ahydrofluoric acid precursor, and optionally contains a phosphonate. Theformation-dissolving fluid may optionally contain a viscosifying agent,in which case it may further optionally contain a proppant and/or abreaker.

BRIEF DESCRIPTION OF DRAWINGS

FIG. 1 shows a schematic of a conventional fracture.

FIG. 2 shows a schematic of a fracture having primary and secondarywormholes.

DETAILED DESCRIPTION

The principles and the methods described below apply to any mineraltype, although they will be discussed in terms of carbonates andsandstones. Formations that are considered to be carbonates may containsome sandstone and vice versa. Also, when we are describing situationsin which the acid reacts with the first material with which it comesinto contact, we will describe the location of that reaction as “nearthe wellbore” although, of course, there can be situations in which thelocation where the majority of the acid first comes into contact withthe formation is farther away, for example when there are natural veryhigh-conductivity streaks,. or fractures or vugs. In this situation,“near the wellbore” should be interpreted as meaning primarily in thelocalized area most readily accessible to the acid.

Numerous studies of the wormholing process in matrix stimulation (forexample carbonate acidizing) have shown that the dissolution patterncreated by the flowing acid occurs by one of three mechanisms (a)compact dissolution, in which most of the acid is spent near thewellbore rock face; (b) wormholing, in which the dissolution advancesmore rapidly at the tips of a small number of highly conductivemicro-channels, i.e. wormholes, than at the wellbore walls; and (c)uniform dissolution, in which many pores are enlarged, as typicallyoccurs in sandstone acidizing. Compact dissolution occurs when acidspends on the face of the formation. In this case, the live acidpenetration is commonly limited to within a few centimeters of thewellbore. Uniform dissolution occurs when the acid reacts under the lawsof fluid flow through porous media. In this case, the live acidpenetration will be, at most, equal to the volumetric penetration of theinjected acid. (Uniform dissolution is also the preferred primarymechanism of conductive channel etching of the fracture faces in acidfracturing, as will be discussed further below.) The objectives of theacidizing process are met most efficiently when near wellborepermeability is enhanced to the greatest depth with the smallest volumeof acid. This occurs in regime (b) above, when a wormholing patterndevelops.

The dissolution pattern that is created depends on the acid flux. Acidflux is the volume of acid that flows through a given area in a givenamount of time. Compact dissolution occurs at relatively low acid flux,wormholes are created at intermediate acid flux, and uniform dissolutionoccurs at high acid flux. There is not an abrupt transition from oneregime to another. As the acid flux is increased, the compact patternwill change to one in which large diameter wormholes are created.Further increases in flux yield narrower wormholes, which propagatefarther for a given volume of acid injection. Finally, as acid fluxcontinues to be increased, more and more branched wormholes appear,leading to a fluid-loss limiting mode and less efficient use of theacid. This phenomenon has a detrimental effect on matrix stimulationefficiency, especially at the rate where branches develop secondarybranches; there are many wormholes, but they do not achieve much depth.Ultimately, then, a virtually uniform pattern is observed. The mostefficient process, in matrix acidizing, is thus one that will createwormholes with a minimum of branching and is characterized by the use ofthe smallest volume of acid to propagate wormholes a given distance.

Wormholing is the preferred dissolution process for matrix acidizing,for example of carbonate formations, because it forms highly conductivechannels efficiently. Hence, optimization of the formation of wormholesis the key to success of such treatments. Injecting acid close to orabove the optimal flux is very crucial to assure a successful carbonateacid treatment because of the risk of compact dissolution that mayresult from a slower acid injection. In other words, injecting acid at ahigh rate will generally promote success in matrix acid treatment, andinjecting acid at the optimal flux rate will ensure the most efficientmatrix acid treatment. However, the optimum is a complex function of theformation properties, acid properties, and acidizing conditions, such astemperature, so that there can be no simple rules as to what rates arebest. The complexity stems directly from the range of dissolutionpatterns created by acid reaction with carbonates. When the acid flux islow, wormhole propagation is hindered due to slow acid convection, andthe wormhole propagation rate is governed by balancing the convectionand molecular diffusion. When the acid flux is high enough, the wormholepropagation is limited mainly by the reaction rate and the wormholegrowth is governed by balancing the surface reaction and moleculardiffusion.

In acid fracturing, on the other hand, in many cases the depth ofstimulation (fracture length) is typically limited by rapid consumption(compact dissolution) of acid near the wellbore and by loss of acidthrough the fracture faces (commonly referred to as fluid leakoff orfluid loss). Fluid leakoff is a dynamic process that is influencedsignificantly by the formation of wormholes that form in the porouswalls of the fracture. In acid fracturing, these wormholes have alwaysbeen considered to be detrimental because they form close to theborehole and divert fluid from the fracture, consume large amounts ofacid, and provide no benefit to the conductivity of the fracture.

We have found that it is advantageous to create propped fractures thathave wormholes in the fracture faces far from the wellbore. This is doneduring a stimulation treatment, either during or after the proppingstep, with proper control of and balance between the reaction rate, thediffusion rate, and the pump rate (that controls the convection rate)for a given injected reactive formation-dissolving fluid, and a givenformation temperature, pressure and composition. Through the control ofthe pump rate and of the fluid reactivity, reactive formation-dissolvingfluid efficiency in creating desirably located wormholes is achieved andthe stimulation is optimized. People skilled in the arts of matrixacidizing and/or acid fracturing have developed data, correlations andmodels of the reactions of reactive fluids with formation minerals.These data, correlations and models have been used in the past to avoidwormholing in acid fracturing and to maximize wormholing in matrixacidizing. Examples are found in U.S. patent application Ser. No.10/065,441, which has a common assignee as the present application, andU.S. Pat. No. 6,196,318. These data, correlations and models can be usedinstead to select fluids and prepare stimulation job designs to promotewormholing in propped fractures.

In generating wormholes in the faces of propped fractures, some of thesame problems would be encountered as in etching fracture faces duringfracture acidizing. That is, care must be taken to ensure that all ormost the acid reaction does not occur too close to the wellbore. It isknown in the art that to achieve maximum effectiveness of the fractureacidizing process, it is often desirable to maximize the time thefracture is exposed to the acid, while limiting the amount of acid usedto an economically reasonable amount. However, in fracture acidizingprocedures used heretofore, less than desired results have often beenachieved when the acid exposure time is maximized. For example, wherethe fracture acidizing treatment of a well formation has been carriedout by first creating a fracture in the formation and then continuing toinject acid into the fracture at a high rate and pressure, in one orseveral stages, the fracture faces adjacent to the well are exposed tothe etching of a lot of acid for a relatively long period of time, andyet the fracture faces furthest from the well may have receivedinsufficient acid contact, even after a large quantity of acid has beeninjected. In some formations, the longer the acid is allowed to etch therock faces adjacent to the well, the more likely that those rock faceswill become softened or over-etched, so that upon closing, the faceswill crush against each other, effectively destroying or restricting theflow channels created adjacent to the well. In other formations, whichreact more slowly, the acid contact time and effective acid penetrationinto the fracture may be insufficient to provide additional flowchannels at a distance not adjacent to the well.

Although we have used and will continue to use the terms acidizing andacid fracturing because they are so ingrained in the industry, insteadof the term “acid” we will often use the term “formation-dissolvingfluid” because acids are not the only reactive fluids that will dissolveformation minerals. In some optimized methods of generating proppedfractures having wormholes extending out from the fracture faces farfrom the wellbore, acids are not the optimal reactive fluids. Associatedwith the theoretical understanding of wormholing are recent advances information-dissolving fluid formulation. We will elaborate further below,but in addition to known gelled acids, emulsified acids, retarded acidswhich use either inorganic or organic acids, or mixtures of theseconventional acids, now new unconventional reactive fluids which usemainly chelant systems, have also been developed and have been shown togenerate wormholes in carbonate reservoir formations when the overallprocess of stimulation is optimized. Examples of unconventionalformation-dissolving fluids include aminopolycarboxylic acids and theirsalts, which are sometimes called “non-acid reactive solutions” or NARSwhen they are basic. In addition, novel self-diverting wormholing acidsystems, that are viscoelastic surfactant systems that change viscositydramatically as a function of pH, are also available for thisapplication that could enhance more generation of wormholes from thefracture surface.

The reactivity of the formation-dissolving fluid may be selected (forexample with the use of fracture and/or acidizing simulator computerprograms) on the basis of the flow rate and formation and fluidparameters. The reactivity of the formation-dissolving fluid can becontrolled by varying the rate of reaction, the rate of mass transfer,or both. For example, the rate of reaction can be decreased by changingthe type of formation-dissolving fluid, by changing the form of thefluid from a solution to an emulsion, by adding appropriate salts (whichchange the equilibrium constant for the surface reaction), or byincreasing the pH of the formation-dissolving fluid. The rate ofreaction can also be decreased by changing the physical processingconditions (e.g., by reducing the pump flow rate and/or pumpingpressure, or by cooling the formation-dissolving fluid using externalcooling means or internal cooling means (e.g., pumping a large padstage, or by adding nitrogen or other gas that is inert in the process).

In general, in creating propped fractures having wormholes in thefracture faces far from the wellbore, simple mineral acids such as HCl,HF, or mixtures of HCl and HF, would be too reactive, and would spendtoo close to the wellbore. It would normally be necessary to use a lessreactive formation-dissolving fluid. Non-limiting examples would beorganic acids (such as acetic or formic acids, whose reactivities couldbe further adjusted by including varying amounts of sodium acetate orsodium formate respectively), chelating agents such asaminopolycarboxylic acids (such as ethylenediaminetetraacetic acid orhydroxyethylethylenediaminetriacetic acid (HEDTA), whose reactivitiescould be further adjusted by converting them partially or completelyinto sodium, potassium or ammonium salts or by adjusting the pH with,for example HCl), or retarded mineral acids (such as gelled oremulsified HCl, whose reactivity could be further adjusted bymanipulation of the choice of and concentration of surfactant and of theoil/water ratio).

The chelating agents useful herein are a known class of materials havingmany members. The class of chelating agents includes, for example,aminopolycarboxylic acids and phosphonic acids and sodium, potassium andammonium salts thereof. HEDTA and HEIDA (hydroxyethyliminodiacetic acid)are useful in the present process; the free acids and their Na, K, NH₄ ⁺salts (and Ca salts) are soluble in strong acid as well as at high pH,so they may be more readily used at any pH and in combination with anyother reactive fluids (e.g., HCl). Other aminopolycarboxylic acidmembers, including EDTA,(nitrilotriacetic acid), DTPA(diethylenetriaminepentaacetic acid), and CDTA(cyclohexylenediaminetetraacetic acid) are also suitable. At low pHthese latter acids and their salts may be less soluble. Examples ofsuitable phosphonic acids and their salts, include ATMP:aminotri(methylenephosphonic acid); HEDP:1-hydroxyethylidene-1,1-phosphonic acid; HDTMPA:hexamethylenediaminetetra (methylenephosphonic acid); DTPMPA:diethylenediaminepentamethylenephosphonic acid; and2-phosphonobutane-1,2,4-tricarboxylic acid. All these phosphonic acidsare available from Solutia, Inc., St. Louis, Mo., USA, as DEQUEST(Registered Trademark of Solutia) phosphonates. Such materials are knownin the oilfield. Prior art treatments did not, however, inject suchfluids into the formation in such a manner as to maintain an optimumwormhole-forming efficiency and they were not as effective as themethods of the subject invention in creating wormholes in the formationextending out from the fracture faces. Particularly preferredchelant-based dissolvers are those containinghydroxyethylaminocarboxylic acids such ashydroxyethylethylenediaminetriacetic acid (HEDTA),hydroxyethyliminodiacetic acid (HEIDA), or a mixture thereof, asdescribed in U.S. Pat. No. 6,436,880, which has a common assignee as thepresent application, and which is hereby incorporated in its entirety.Fluids containing such chelants may be viscosified.

Particularly preferred self-diverting wormholing acid systems are thosemade from solutions of certain surfactants, in particular certainbetaines, optionally in conjunction with co-surfactants or loweralcohols. Examples are described in U.S. Pat. No. 6,399,546, U.S. patentapplication Ser. No. 10/054,161, and U.S. patent application Ser. No.10/065,144, all of which have a common assignee as the presentapplication, and all of which are hereby incorporated in their entirety.A highly-preferred self-diverting acid is made from erucic amidopropyldimethyl betaine. These self-diverting wormholing acid systems have theimportant property that they have water-like viscosities as formulated(when they are strongly acidic) but their viscosities increasedramatically as the pH is increased above a value of about 2 to 2.5 asthey react.

Conventional propped hydraulic fracturing methods, with appropriateadjustments if necessary, as will be apparent to those skilled in theart, are used in the methods of the invention. One preferred fracturestimulation treatment according to the present invention typicallybegins with a conventional pad stage to generate the fracture, followedby a sequence of stages in which a viscous carrier fluid transportsproppant into the fracture as the fracture is propagated. Typically, inthis sequence of stages the amount of propping agent is increased,normally stepwise. The pad and carrier fluid can be, and usually are, agelled aqueous fluid, such as water or brine thickened with aviscoelastic surfactant or with a water soluble or dispersible polymersuch as guar, hydroxypropylguar or the like. The pad and carrier fluidsmay contain various additives. Non-limiting examples are fluid lossadditives, crosslinking agents, clay control agents, and mobilitycontrol agents such as fibers, breakers and the like, provided that theadditives do not affect the stability or action of theformation-dissolving fluid.

The procedural techniques for pumping fracture stimulation fluids down awellbore to fracture a subterranean formation are well known. The personthat designs such fracturing treatments is the person of ordinary skillto whom this disclosure is directed. That person has available manyuseful tools to help design and implement the fracturing treatments, oneof which is a computer program commonly referred to as a fracturesimulation model (also known as fracture models, fracture simulators,and fracture placement models). Most if not all commercial servicecompanies that provide fracturing services to the oilfield have one ormore fracture simulation models that their treatment designers use. Onecommercial fracture simulation model that is widely used by severalservice companies is known as FracCADE™. This commercial computerprogram is a fracture design, prediction, and treatment-monitoringprogram that was designed by Schlumberger, Ltd. All of the variousfracture simulation models use information available to the treatmentdesigner concerning the formation to be treated and the varioustreatment fluids (and additives) in the calculations, and the programoutput is a pumping schedule that is used to pump the fracturestimulation fluids into the wellbore. The text “Reservoir Stimulation,”Third Edition, Edited by Michael J. Economides and Kenneth G. Nolte,Published by John Wiley & Sons, (2000), is an excellent reference bookfor fracturing and other well treatments; it discusses fracturesimulation models in Chapter 5 (page 5-28) and the Appendix for Chapter5 (page A-15)), which are incorporated herein by reference.

In certain preferred embodiments, because the fracture area availablefor inflow of fluids into the wellbore is increased by the creation ofwormholes, it is not necessary to generate a long fracture in theformation. In that case, to save fluids, hydraulic horsepower, time andmoney, a tip screenout may be desirable. In a tip screenout, the solidsconcentration at the tip of the fracture becomes so high due to fluidleak-off into the formation that the slurry is no longer mobile. Theconcentrated proppant slurry plugs the fracture, preventing additionalgrowth of the fracture length. Additional pumping of the proppant/fluidslurry into the formation after the screenout occurs causes the fractureto balloon. The fracture grows in width rather than length, and largeconcentrations of proppant per surface area are placed in the fracture.Jobs may be deliberately designed to increase the probability of tipscreenouts, and additional steps may be taken to induce tip screenouts,for example by the methods described in U.S. patent application Ser.Nos. 10/214,817 and 10/227,690 both of which have a common assignee asthe present application.

Many of the formation-dissolving fluids of the invention, such as acids,would have an added advantage of being breakers for polymers, or forsome of the surfactants and/or the micelles in VES″s. Another advantageto the method is that it would allow the operator to push liveformation-dissolving fluid out further and more quickly because some ofthe volume of the fracture would already be taken up by proppant.Another advantage is that the operator would be able to pump into apropped fracture at much lower pressures, which would be an economicadvantage. This would also allow the formation-dissolution step to bedone at the optimal flow rate for wormholing in the right locationrather than at a flow rate dictated by the need to keep the fractureopen.

FIG. 1 (not to scale) schematically shows a top view (assuming anapproximately vertical fracture) of one half of a fracture [1] extendingfrom a wellbore [2] into a formation. Not shown is the other half of thefracture extending in approximately the opposite direction from thewellbore. If the fracture is propped, the fracture would be filledthroughout most of its volume with proppant (not shown). If the fracturewas made by acid fracturing, the faces [3] of the fracture would beetched with channels (not shown). FIG. 2 shows a fracture havingwormholes (primary channels) [4] extending from the faces of thefracture out into the formation and additional wormholes [5] (secondarychannels) extending from the primary channels.

In conventional fractures such as the one shown in FIG. 1, the pathwayavailable for fluids in the formation, at any appreciable distance fromthe fracture, to flow into the fracture is limited by the surface areaof the faces of the fractures. The fluids must flow through theformation until they reach the fracture, and the permeability of theformation is much lower than that of the fracture. Local surface areaincreases right at the faces of the fracture due to differentialetching, compact dissolution, or uniform dissolution do not decrease thelength of the pathway that fluids must follow through the formationuntil they reach a high-permeability flow path; that is, they do notincrease the effective surface area. However, wormholes, which are highfluid permeability channels that extend into the formation, do aid inthe flow of fluids from the formation into the fracture, because theyafford fluids opportunities to enter high permeability channels whenthey are still far from the fracture. When there are some secondarychannels (secondary wormholes) branching off the main channels (primarywormholes) the opportunities may be even greater. The propped fractureshaving wormholes may be created in all types of formations, for exampledeep, hot carbonate formations and shallow, high permeability sandstoneformations. When sandstone formations are treated, theformation—dissolving fluid preferably contains hydrofluoric acid, andmay contain a phosphonate, such as by non-limiting example aphosphonate-containing polymer or diethylene triamine penta-(methylenephosphonic acid).

Specific methods of forming wormholes extending from the faces ofpropped fractures into a formation fall into two categories: a) a methodin which a closed propped fracture is formed and then the wormholes areformed, and b) a method in which the fracture and channel system isformed before the closure occurs. The later steps of an approach inwhich a closed propped fracture is formed and then the wormholes areformed can also be used remedially, that is to improve the performanceof a previously formed propped fracture. Any of the methods can also beused where there are already naturally occurring fractures or vugs(either or both of which we will call “fissures”) in the formation thatare in contact with the wellbore, either directly or as a consequence ofthe creation of a hydraulic fracture. It should be understood that thewormhole-creating formation-dissolution fluids and methods of theInvention are effective at rates and pressures above or below thefracture rates and pressures for any formation. It should also beunderstood that when a formation-dissolving fluid is being injectedunder optimized wormhole-creating conditions, then in general the longerthe pumping is continued, the deeper the wormholes will penetrate intothe formation and the better the results will be. Finally it should beunderstood that mechanical or chemical diverters may be used to ensurethat the fluids used enter the formations of interest.

Methods of forming propped fractures with wormholes have been tried inthe past, but generally have been unsatisfactory, not only because thedynamics of wormhole formation were not well understood and the computerprograms available for determining the optimal job designs wereinadequate, but also because certain formation-dissolving fluids wereunavailable. For example, even with retarded acids, the acid would notpenetrate the length of the propped fracture. Two new types of fluidshave recently been developed that help make these methods possible,especially for treatment of carbonates. (When sandstone formations aretreated, the formation-dissolving fluids preferably contain hydrofluoricacid, and may contain a phosphonate, such as by non-limiting example aphosphonate-containing polymer or diethylene triamine penta-(methylenephosphonic acid).)

The two new types of fluids referred to above are suitable at differenttemperatures. At lower temperatures, for example below about 300° F., afairly strong formation-dissolving fluid must be used, so the key tosuccess is to ensure that the wormholes are not all formed too close tothe wellbore. At higher temperatures, for example above about 300° F., afluid is needed that is not too reactive at low temperatures but doesreact at higher temperatures. We have found that surfactant-based fluidsthat have a low viscosity (approximately comparable to that of waterunder comparable conditions) when they are formulated in strong acid butdevelop micellar structures that have high viscosities when the acidspends and the pH rises to about 2 to about 2.5 are particularlysuitable at the lower temperatures. These materials, called“viscoelastic diverting acids” or VDA″s, have the additional valuableproperty that they lose the high viscosity when they are contacted withformation fluids, either formation water, condensate or oil. (If theprincipal fluid in the formation is a hydrocarbon that would be a gas atsurface pressures, for example methane, there are breakers availablethat can destroy either the micellar structure or the surfactantitself.) Examples of VDA″s were given above.

The methods will be described without discussions of the pad, althoughit is to be understood that pads are generally used. To use a VDA in amethod in which a closed propped fracture is formed and then thewormholes are formed, a conventional hydraulic fracture is generatedwith conventional polymeric viscosifiers in the carrier fluid. Thecarrier fluid may contain breakers, breaker aids, and clean-upadditives. The fracture is allowed to close and time is allowed for thefluid to break if necessary; the fracture may also optionally be flowedback. At this stage, the fracture contains proppant and either brokenfracture fluid or formation fluid. The low-viscosity, high-acidity VDAis then injected at a pressure below fracture pressure and at a flowrate calculated to favor wormholing, especially a network of branchedwormholes, when the temperature, VDA acid concentration and formationproperties are taken into account. Not to be limited by theory, but itis believed that the VDA″s works in the present process as follows. Thefirst of the VDA fluid injected creates a wormhole or network ofwormholes at or near the wellbore. However, as the acid spends, theviscosity of the VDA in the initially generated wormhole or network ofbranched wormholes, increases and subsequently injected acid cannot flowinto the wormhole but rather flows farther into the fracture andinitiates generation of another wormhole or network of branchedwormholes. As the acid spends, the viscosity of that VDA also increasesand the process is repeated progressively farther and farther away fromthe borehole until wormholes have been generated at many points on theface of the original fracture. After the wormhole-generating VDAinjection is stopped, the viscosity of the VDA in the wormholes isreduced, either because of the inherent instability of the micelles orthe surfactant due to time and temperature, or by breakers included inthe original VDA formulation, or by reducing the wellhead pressure andreversing the flow and allowing formation fluids to contact the VDA.

The fluids used at higher temperatures are chelating agents as describedabove. Particularly preferred examples are chelant-based dissolverscontaining hydroxyethylaminocarboxylic acids such ashydroxyethylethylenediaminetriacetic acid (HEDTA),hydroxyethyliminodiacetic acid (HEIDA), or a mixture thereof, asmentioned above. These materials have low reactivity, low viscosity, buthigh dissolving capacity. Previously available formation-dissolvingfluids were strong acids, retarded acids, or organic acids. The reasonswhy strong acids cannot be used have been made very evident. Retardedacids cannot be used because they are either viscous or emulsions;neither form of fluid can be injected into a propped fracture withoutvery deleterious results. Viscous fluids would require high hydraulichorsepower and/or would have to be pumped at very low rates to preventfracture propagation and/or would displace proppant from the nearwellbore region of the fracture. In addition to possibly being viscous,maintaining the stability of emulsions at high temperatures and in flowthrough a proppant pack would be difficult. Adding an oil-wettingsurfactant to aqueous acid to form an emulsion in an effort to create abarrier to acid migration to the rock surface often requires continuousinjection of oil during the treatment. Moreover these systems are oftenineffective at high formation temperatures and high flow rates sinceabsorption of the surfactant on the formation rock is diminished.Emulsified acid systems are also limited by increased frictionalresistance to flow. Organic acids are not suitable because they are farmore expensive than mineral acids, and, while they have a lower reactionrate, they also have a much lower reactivityin fact, they do not reactto completion, but rather an equilibrium with the formation rock isestablished. Hence one mole of HCl yields one mole of available acid(i.e., H⁺), but one mole of acetic acid yields substantially less thanone mole of available acid. However, because the described chelant-basedmaterials have low reactivity at high temperature, low viscosity, buthigh dissolving capacity, they can be injected into propped fractures atthe rates required to generate wormholes without propagating fracturesor displacing proppant.

For the same reasons, these two types of fluids are preferred (althoughothers can be used) in the second category of methods of forming proppedfractures having wormholes extending from their faces into theformation: those in which the entire fracture and channel system isformed before the closure occurs. There are four variations on thisapproach:

First, the carrier fluid in the early proppant-transporting stages is aconventional polymer-viscosified aqueous fluid and the carrier fluid inthe later proppant-transporting stages is a viscous formation-dissolvingfluid. Each is injected at pressures and rates sufficient to generateand propagate fractures. By non-limiting example, the carrier fluid inthe early stages is viscosified with guar or a substituted guarcontaining a breaker such as an oxidizing agent and/or enzyme. A fluidthat does not dissolve the formation is used in these stages so that afracture of the desired size and shape is generated without the problemsthat would be encountered if the carrier fluid were to react with theformation near the wellbore. Since the effective surface area of thefracture is going to be increased next by the generation of a wormholesystem away from the wellbore, the fracture need not necessarily be longand so optionally the job is designed so that a tip screenout occurs.The viscosified formation-dissolving carrier fluid in the remainingstages is by non-limiting example a viscoelastic surfactant-basedmicellar system containing an acid or a chelating agent or both. Theviscosity of such a system depends upon such factors as the surfactantconcentration, the environment (such as the pH and the nature andconcentration of salts), the time, the temperature, and the presence ofother components such as alcohols, co-surfactants and breakers. Thereactivity of such a system depends upon some of the same factors aswell as on the nature and concentration of the formation-dissolvingcomponent. The nature of these dependencies are known, and thus therelative rates at which this carrier fluid loses viscosity and reactswith the formation are adjusted, and taking into account the flow ratenecessary to maintain the needed pressure and to transport proppant, thesystem is designed so that this viscosified formation-dissolving carrierfluid transports proppant into the fracture and then reacts with theformation to create wormholes, simultaneously or subsequently losing itsviscosity. In a particularly preferred embodiment, the viscosifiedformation-dissolving carrier fluid is a VDA. As is almost always thecase, laboratory experiments and/or computer modeling are used tooptimize this and the other job designs.

Second, the fracture is created with a VDA, optionally containing achelant, which has sufficient viscosity and leak-off control to create afracture of the desired dimensions. As was explained above in thedescription of the approach in which a closed propped fracture is formedand then the wormholes are formed, the conditions are adjusted so thatthe VDA forms a successive sequence of wormholes farther and fartherfrom the borehole. This may occur during fracture growth or after thefinal fracture length has been achieved, that is, the pumping rate maybe reduced at some point so that the loss of fluid due to wormholeformation is balanced by pumping to keep the fracture open. Then,proppant-laden stages, viscosified with polymeric or VES viscosifiers,are injected to fill the fracture with proppant. This is done at apressure and flow rate at least sufficient to hold the fracture open.Optionally, the job is designed so that a tip screenout occurs as soonas, or shortly after, the start of proppant stages so that the fracturetends to widen rather than lengthen. Fracture propagation and/orwormhole formation may optionally occur during the proppant-placingstage as well. This embodiment has the advantage that the wormholes maybe filled with proppant.

Third, a propped fracture is created with a conventional polymeric orVES-based viscosified carrier fluid and then, while the fracture is heldopen, a formation-dissolving fluid, such as a VDA, is injected. Thecarrier fluid may contain a breaker, or a breaker may be injected withthe formation-dissolving fluid. The VES, if used, is a system that wouldbe a VDA if it were strongly acidic. In this sequence, the VDA breaksthe polymer or the VES (either of which is chosen such that it can bebroken by strong acids), so that the VDA can reach deep into the proppedfracture and form wormholes as has been described above. If the carrierfluid is not fully broken by the formation-dissolving fluid front, someadditional fracture propagation may occur (which could be beneficial)and some proppant may be moved away from the wellbore. Mobility-reducingagents such as fibers, or the use of resin-coated proppants can helpprevent proppant movement further into the fracture, if desired.Alternatively, a final proppant-carrying viscosified stage or stages areused to replace proppant in the near-wellbore region of the fracture. Ina preferred embodiment, the carrier fluid is a VES and theformation-dissolving fluid is a VDA. In a most-preferred embodiment, thepad, the carrier fluid, and the formation-dissolving fluid all containerucic amidopropyl dimethyl betaine.

Finally, a propped fracture is created with a viscous,formation-dissolving carrier fluid that has sufficient viscosity andleak-off control to create a propped fracture of the desired dimensions.The conditions can be adjusted so that leak off of some of the viscous,formation-dissolving carrier fluid will form wormholes along thefracture during fracture growth, and optionally so that the wormholesare extended during and after fracture closure. Optionally, the job isdesigned so that a tip screenout occurs. This embodiment also has theadvantage that the wormholes may be filled with proppant.

All of the fluids injected in the methods of the invention, such as thepad, the viscous proppant-carrying fluid and the formation-dissolvingfluid, may contain various additives well known in stimulationtreatments (such as, for example, corrosion inhibitors, iron controlagents, surfactants, clay control additives, buffers, scale inhibitorsand the like) provided that the additives do not interfere with thedesired action or stability of the fluid. It would be expected, andwithin the scope of the invention, to conduct laboratory tests or runcomputer simulations to ensure that such additives were suitable.

Although the methods have been described here for, and are mosttypically used for, hydrocarbon production, they may also be used ininjection wells and for production of other fluids, such as water orbrine.

1-24. (canceled)
 25. A method of forming a fracture having increasedeffective surface area for the inflow of fluids into said fracture froma subterranean formation penetrated by a wellbore comprising thesequential steps of: a. injecting a polymeric viscous carrier fluidcontaining proppant at a rate and pressure sufficient to fracture saidformation; b. injecting a formation-dissolving viscous carrier fluidcontaining proppant at a rate and pressure sufficient to hold saidfracture open; and c. allowing said fracture to close.
 26. The method ofclaim 25 wherein a tip screenout is induced in said step of injecting apolymeric viscous carrier fluid containing proppant at a rate andpressure sufficient to fracture said formation.
 27. The method of claim25 wherein said polymeric viscous carrier fluid comprises a breaker. 28.The method of claim 25 wherein said formation-dissolving viscous carrierfluid comprises a surfactant-based viscoelastic fluid.
 29. The method ofclaim 25 wherein said formation-dissolving viscous carrier fluidcomprises a self-diverting acid.
 30. The method of claim 25 wherein saidformation-dissolving viscous carrier fluid comprises a breaker.
 31. Themethod of claim 25 wherein the subterranean formation is a sandstone andthe formation-dissolving fluid comprises a component selected from thegroup consisting of hydrofluoric acid and a hydrofluoric acid precursor.32. The method of claim 31 wherein the formation-dissolving fluidfurther comprises a phosphonate.
 33. The method of claim 25 wherein saidstep of injecting a formation-dissolving viscous carrier fluidcontaining proppant is carried out at a rate and pressure sufficient topropagate said fracture.
 34. A method of forming a fracture havingincreased effective surface area for the inflow of fluids into saidfracture from a subterranean formation penetrated by a wellborecomprising the sequential steps of: a. injecting a formation-dissolvingviscous fluid at a rate and pressure sufficient to fracture saidformation; b. injecting a viscous carrier fluid containing proppant at arate and pressure sufficient to hold said fracture open; and c. allowingsaid fracture to close.
 35. The method of claim 34 wherein theformation-dissolving fluid comprises a component selected from the groupconsisting of self-diverting acid, aminopolycarboxylic acid, andaminopolycarboxylic acid salt.
 36. The method of claim 35 wherein theaminopolycarboxylic acid is hydroxyethylethylenediamine triacetic acid.37. The method of claim 35 wherein the aminopolycarboxylic acid salt istrisodium hydroxyethylethylenediamine triacetate adjusted to a pH ofabout 4 with hydrochloric acid.
 38. The method of claim 34 wherein saidviscous carrier fluid further comprises a breaker.
 39. The method ofclaim 34 wherein the subterranean formation is a sandstone and theformation-dissolving fluid comprises a component selected from the groupconsisting of hydrofluoric acid and a hydrofluoric acid precursor. 40.The method of claim 39 wherein the formation-dissolving fluid furthercomprises a phosphonate.
 41. A method of forming a fracture havingincreased effective surface area for the inflow of fluids into saidfracture from a subterranean formation penetrated by a wellborecomprising the sequential steps of: a. injecting a viscous carrier fluidcontaining proppant at a rate and pressure sufficient to fracture saidformation; b. injecting a formation-dissolving fluid at a rate andpressure sufficient to hold said fracture open; and c. allowing saidfracture to close.
 42. The method of claim 41 wherein theformation-dissolving fluid comprises a component selected from the groupconsisting of self-diverting acid, aminopolycarboxylic acid, andaminopolycarboxylic acid salt.
 43. The method of claim 42 wherein theaminopolycarboxylic acid is hydroxyethylethylenediamine triacetic acid.44. The method of claim 42 wherein the aminopolycarboxylic acid salt istrisodium hydroxyethylethylenediamine triacetate adjusted to a pH ofabout 4 with hydrochloric acid.
 45. The method of claim 41 wherein a tipscreenout is induced in said step of injecting a viscous carrier fluidcontaining proppant at a rate and pressure sufficient to fracture saidformation.
 46. The method of claim 41 wherein said viscous carrier fluidfurther comprises a breaker.
 47. The method of claim 41 wherein thesubterranean formation is a sandstone and the formation-dissolving fluidcomprises a component selected from the group consisting of hydrofluoricacid and a hydrofluoric acid precursor.
 48. The method of claim 47wherein the formation-dissolving fluid further comprises a phosphonate.49. The method of claim 41 further comprising a step of injecting aviscous carrier fluid containing proppant, at a rate and pressuresufficient to hold said fracture open, after injection of saidformation-dissolving fluid and prior to allowing said fracture to close.50. The method of claim 49 wherein said viscous carrier fluid furthercomprises a breaker.
 51. The method of claim 41 wherein the viscouscarrier fluid and the formation-dissolving fluid each comprise erucicamidopropyl dimethyl betaine.
 52. A method of forming a fracture havingincreased effective surface area for the inflow of fluids into saidfracture from a subterranean formation penetrated by a wellborecomprising the sequential steps of: a. injecting a formation-dissolvingviscous carrier fluid containing proppant at a rate and pressuresufficient to fracture said formation; and b. allowing said fracture toclose.
 53. The method of claim 52 wherein a tip screenout is induced insaid step of injecting a polymeric viscous carrier fluid containingproppant at a rate and pressure sufficient to fracture said formation.54. The method of claim 52 wherein said formation-dissolving viscouscarrier fluid comprises a surfactant-based viscoelastic fluid.
 55. Themethod of claim 52 wherein said formation-dissolving viscous carrierfluid comprises a self-diverting acid.
 56. The method of claim 52wherein said formation-dissolving viscous carrier fluid comprises abreaker.
 57. The method of claim 52 wherein the subterranean formationis a sandstone and the formation-dissolving fluid comprises a componentselected from the group consisting of hydrofluoric acid and ahydrofluoric acid precursor.
 58. The method of claim 57 wherein theformation-dissolving fluid further comprises a phosphonate. 59-67.(canceled)